Solar, battery storage, and wind accounted for 90% of all new U.S. power plant capacity brought online in the first half of 2026, with Texas, New Mexico, and Arizona installing the largest volumes, extending a multi-year shift that has effectively crowded out new gas and coal additions. The milestone arrives even as the renewable sector navigates supply-chain bottlenecks, interconnection queue backlogs, and policy uncertainty following the 2025 midterm elections, signaling that the economic and operational logic of zero-marginal-cost generation has overridden near-term headwinds.
How the 90% Share Was Built: Market Mechanics Behind the Headline
The 90% figure for H1 2026 is not an anomaly – it is the culmination of a trajectory that has seen renewable-and-storage shares climb from roughly 70% in 2022 to the mid-80s by 2024, according to EIA capacity-addition reports. What distinguishes the first half of 2026 is the growing weight of standalone and co-located battery storage, which now regularly exceeds 20% of quarterly additions on a nameplate basis. In ERCOT alone, developers commissioned more than 4.5 GW of new storage in the first six months, a pace that would have been unimaginable three years ago when the fleet totaled barely 2 GW.
Texas, New Mexico, and Arizona lead for structural reasons that go beyond sunshine. ERCOT’s energy-only market rewards fast-ramping resources that can arbitrage daily price spreads, and its relatively streamlined interconnection process – compared with PJM or MISO – lets projects reach commercial operation in 18-24 months rather than four-plus years. New Mexico benefits from high insolation, abundant land, and proximity to California demand via Path 49 and the newly upgraded Western Spirit transmission line. Arizona’s build-out is driven by utility IRP mandates from APS and TEP, which have committed to 100% clean energy by 2050 and 2032 respectively, forcing near-term procurement that shows up in the 2026 data.
Wind’s contribution, while smaller than solar in absolute MW, remains critical for diversity. The High Plains corridor – stretching from the Texas Panhandle through Oklahoma and Kansas – continues to deliver capacity factors above 45%, making it the cheapest firming partner for midday-heavy solar. However, new wind interconnection requests have slowed in SPP and MISO because the best sites are already taken or constrained by transmission limits that won’t relax until the next round of regional planning projects (the so-called “JTI” portfolio in SPP and LRTP in MISO) energize in 2028-2030.
Cross-Cutting Dynamics: Gas, Interconnection Reform, and the Storage Revenue Stack
The near-total absence of new combined-cycle gas turbines in the H1 2026 data reflects a fundamental shift in the revenue stack. Ten years ago, a gas plant could count on capacity payments, energy margins, and ancillary services to clear a 15-year payback. Today, capacity prices in PJM’s BRA have collapsed below $30/MW-day – roughly one-fifth of their 2022 peak – because the auction is flooded with solar-plus-storage offers that qualify as capacity resources under ELCC rules. In ERCOT, which has no capacity market, the economics are even starker: a new gas peaker needs roughly 500 hours of scarcity pricing above $1,000/MWh to cover fixed costs, but battery deployment has already truncated the duration and frequency of those scarcity events.
That points to a structural ceiling for new gas construction that is lower than most integrated resource plans assume. If storage continues to be added at the H1 2026 run rate – roughly 1.5 GW per month nationally – the cumulative four-hour-equivalent fleet could reach 60 GW by end-2027, enough to cover the majority of daily net-load ramps in every major ISO. At that point, the marginal value of an additional gas peaker drops toward zero, and the only remaining gas build case is for hydrogen-ready combined cycle units tied to specific industrial offtake or reliability-must-run designations.
Interconnection reform is the other cross-cutting force. FERC Order 2023, which took effect in late 2024, replaced the serial “first-ready, first-served” queue with a cluster-based, readiness-deposit system. Early data from PJM’s first post-Order 2023 cycle shows a 30% reduction in withdrawn projects and a median study timeline cut from 42 to 28 months. If that holds, the 2.6 TW national queue – roughly 95% solar, wind, and storage – could begin converting to steel-in-the-ground at a faster clip, reinforcing the 90% share rather than reversing it. The risk is that readiness deposits favor well-capitalized developers, potentially squeezing out smaller community-solar and distributed-wind projects that lack balance-sheet depth.
On the cost side, the learning curve for lithium-ion battery packs has resumed its descent after a 2022-2023 plateau. BloombergNEF’s 2025 survey places average pack prices at $115/kWh, down 18% year-over-year, driven by LFP chemistry scaling in China and the first U.S. gigafactories (notably the Form Energy iron-air plant in West Virginia and the CATL-Ford JV in Michigan) reaching nameplate output. That translates to roughly $220/kWh installed for a four-hour system – a level where storage-plus-solar LCOE undercuts new gas peakers in every NERC region except the Northeast, where winter reliability constraints still favor dual-fuel capability.
Who This Affects
- Utility resource planners: IRPs filed in 2025-2026 that assume significant new gas capacity after 2028 are increasingly misaligned with market reality; planners should re-run scenarios with storage ELCC values above 80% for four-hour duration and zero new gas builds as a base case.
- Storage developers: The revenue stack is shifting from energy arbitrage toward ancillary services and capacity payments; in ERCOT, regulation-up/down and RRS now contribute 40-50% of typical battery revenue, so bidding strategies and contract structures must evolve accordingly.
- Transmission planners and RTOs: The geographic concentration in Texas, New Mexico, and Arizona means new 345 kV and 500 kV corridors – such as the proposed Permian-to-Dallas HVDC line and the SunZia Southwest expansion – are no longer optional; they are prerequisites for the next 50 GW of renewable integration.
- Gas turbine OEMs and EPC firms: The addressable market for new large-frame gas turbines in the U.S. has likely peaked; pivoting to hydrogen-capable upgrades, retrofits for cycling duty, and international markets (especially Southeast Asia and the Middle East) is now a survival imperative.
- State policy offices: The 90% share validates clean-energy standards but exposes a gap in long-duration storage procurement targets; only California, New York, and Colorado have explicit multi-hour (8+ hour) storage mandates, leaving a reliability gap for multi-day winter events.
What to Watch Next
- ERCOT’s summer 2026 scarcity pricing hours: If battery deployment keeps price spikes below the $5,000/MWh cap for more than 95% of peak-net-load hours, the economic case for new gas peakers in Texas effectively closes.
- PJM’s 2026/27 capacity auction results (expected October 2026): A clearing price below $20/MW-day would confirm that solar-plus-storage is permanently suppressing capacity revenues for thermal assets.
- FERC Order 2023 cluster-study completion rates in MISO and SPP (Q4 2026 data): Faster study timelines should accelerate commercial operation dates for projects currently in the 2027-2029 window, pulling forward the 90% trend.
- Domestic LFP and iron-air factory utilization rates (Q3 2026 earnings calls): Sustained >85% utilization at Form Energy, CATL-Ford, and the new Panasonic Kansas plant would signal that supply-chain constraints have fully lifted, enabling even faster storage build-outs in 2027.
- Western ISO formation (CAISO extended day-ahead market expansion): If the PacifiCorp, NV Energy, and Arizona utilities join by early 2027, the regional diversity benefit could reduce curtailment in Arizona and New Mexico by 15-20%, improving project economics and reinforcing the Southwest build cluster.
Bottom Line
The 90% renewable-and-storage share in H1 2026 is not a cyclical peak – it is the new structural baseline for U.S. capacity additions, driven by economics that now favor zero-marginal-cost resources even without incremental federal subsidies. The only forces that could materially alter this trajectory are a sustained reversal in battery cost declines (unlikely given current factory ramps) or a transmission build-out failure that strands gigawatts of ready-to-build projects in interconnection queues. For every other stakeholder – utilities, developers, regulators, investors – the planning assumption must shift from “how much gas do we need?” to “how fast can we integrate the renewables and storage already queued?”
Read the full report at Energy Central
Note: facts and figures attributed above to reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
Leave a Reply